2.85 mw lethbridge biogas/cogeneration facilty project … · 2.85 mw lethbridge...

2.85 MW LETHBRIDGE BIOGAS/COGENERATION FACILTY

PROJECT ID #G101234

FINAL REPORT (Non-Confidential)

March 2011 – November 2013

Final Report – Non-Confidential Lethbridge Biogas, December 1, 2013 of 66

CCEMC Project ID # G101234

Table of Contents

1. EXECUTIVE SUMMARY .......................................................................................... 4

2. BACKGROUND ...................................................................................................... 5

2.1 Climate Change Emission Management (CCEMC) Corporation ................................... 5 2.2 Lethbridge Biogas General Partner Inc. (LBGP) ............................................................ 5 2.3 ECB Enviro North America Inc. (ECB NA) ...................................................................... 6 2.4 PlanET Biogas (PlanET) .................................................................................................. 7

3. FINAL OUTCOMES REPORT .................................................................................... 8

3.1 Project Technology ....................................................................................................... 8 3.1.1 Receiving/Unloading Technology ................................................................................. 8 3.1.2 Air Cleaning Technology ............................................................................................. 10 3.1.3 Technical Container .................................................................................................... 10 3.1.4 Anaerobic Digestion Technology ................................................................................ 10 3.1.5 Biogas Cleaning & Biogas Conditioning Technology ................................................... 11 3.1.6 Co-Generation Technology ......................................................................................... 12 3.1.7 Emergency Flare .......................................................................................................... 12 3.1.8 Control System & Visualization Software ................................................................... 13 3.1.9 Other Infrastructure .................................................................................................... 13 3.2 Regulatory Approvals .................................................................................................. 14 3.3 Project Innovations ..................................................................................................... 15 3.4 Project Performance ................................................................................................... 15 3.4.1 Feedstock .................................................................................................................... 15 3.4.2 Electricity Production .................................................................................................. 17 3.4.3 GHG Emission Reductions ........................................................................................... 19 3.5 Project Impact ............................................................................................................. 21

4. FINAL FINANCIAL REPORT ................................................................................... 22

4.1 Project Expenses ......................................................................................................... 22 4.2 Project Contributions .................................................................................................. 22 4.3 Project Revenues ........................................................................................................ 22

5. CONCLUSION & NEXT STEPS ................................................................................ 23

Appendices

• Attachment A: Construction & Commissioning Activities (August 2011 November 2013) • Attachment B: Technical Description Cogeneration Unit JMS 420 GS-B.L • Attachment C: Lethbridge Biogas Organic Feedstock List • Attachment D: ESRD Letter September 30, 2013



Contact Information: Office: Lethbridge Biogas General Partner Inc. c/o Box 1119, Fort Macleod, Alberta, Canada, T0L 0Z0 Telephone: (403) 553-4255 Facsimile: (403) 553-0311 E-mail: [email protected] Web site: www.ecbna.com Plant: Lethbridge Biogas LP 4456 8th Avenue North, Lethbridge, Alberta, Canada, T1H 6W5 Telephone: (587) 220-5163 Facsimile: TBD E-mail: [email protected]

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1. EXECUTIVE SUMMARY Lethbridge Biogas General Partner Inc., in its capacity as managing partner of Lethbridge Biogas LP, a limited partnership between ECB Enviro North America Inc. and PlanET Biogas, has developed, built and commissioned a 2.85 MW biogas/cogeneration facility located in Section 3, Township 9, Range 21, West of the 4th Meridian, immediately east of the City of Lethbridge east boundary. The facility is unique in its process design, technology scope and scale and is the first one of its kind in Alberta and all over Canada. It uses advanced anaerobic digester technology to extract biogas from organic feedstock (liquid & solid) in a technically controlled anaerobic environment. It is producing increasing quantities of biogas generated electricity since late August of 2013. Since digester filling began in early June of 2013, the facility:

• Has processed more than 25,000 t of liquid and solid organic feedstock • Has produced more than 6,000 MWh of electricity (natural gas and biogas) • Has achieved a stable biogas production to have one of the co-generation units

exclusively operating on biogas for 24/7 • Is expected to have an estimated initial reduction of GHG emissions for 2013 between

500 -1,000 t CO2e • Has created economic, environmental and societal benefits for the region through

waste reduction, energy creation and advanced technology application Eligible project expenses total $28,575,741 until November 30, 2013 and project contributions provided by CCEMC and the project partners are as follows:

• Agriculture Financial Services Corporation (AFSC): $ 5,000,000 • Climate Change and Emissions Management (CCEMC) Corporation: $ 8,200,000

(incl. holdback) • Department of Energy: $ 6,448,016 • PlanET: $ 8,200,000 • Lethbridge Biogas: $ 727,725

Project revenues until November 30, 2013, predominantly received from electricity sales to the AESO, total $826,327. The implementation of the thermal hydrolysis process (THD) will be the major focus for Lethbridge Biogas in 2014. It is anticipated that the system will be delivered, installed and commissioned in Q3/Q4 of 2014.



2. BACKGROUND

2.1 Climate Change Emission Management (CCEMC) Corporation

In April 2007, Alberta became the first jurisdiction in North America to pass climate change legislation requiring large emitters to reduce emissions. Alberta’s Specified Gas Emitters Regulation (SGER) identifies that companies that emit more than 100,000 metric tonnes of carbon dioxide equivalent per year must reduce emissions intensity by 12 per cent below their 2004-2005 baseline intensity. Organizations that are unable to meet their targets have three compliance options:

• Improve the energy efficiency of their internal operations;

• Buy carbon credits from other Alberta-based organizations; or

• Pay $15 into the Climate Change and Emissions Management Fund for every tonne they exceed the allocated limit.

The Climate Change and Emissions Management (CCEMC) Corporation was created in 2009 to be a key part of Alberta’s climate change strategy and movement toward a stronger and more diverse lower carbon economy. It receives money from the Climate Change and Emissions Management Fund and directs it towards innovative projects that will reduce greenhouse gas emissions. Priority areas for funding by the CCEMC are aligned with Alberta’s 2008 Climate Change Strategy and include:

• Conserving and Using Energy Efficiently (emissions target of 24MT by 2050);

• Implementing CCS (emissions target of 139MT by 2050); and

• Greening Energy Production (emissions target of 37 MT by 2050).

2.2 Lethbridge Biogas General Partner Inc. (LBGP)

LBGP, initially set up as the managing partner for a limited partnership between ECB Enviro North America Inc. (ECB NA) and StormFisher Biogas, submitted an Expression of Interest (EOI) to build a 3.2 MW biogas/ cogeneration facility under the ‘Renewable Energy’ category on September 30, 2009. Project objectives were to:



• Provide a safe, sutainable & cost-efficient alternative disposal option for manure, organic by-products & animal by-products that currently contribute to the release of greenhouse gas emissions (GHG)

• Generate 3.2MW of base-load green electricity & reduce GHG emission through the

use of renewable sources

• Produce an organic fertilizer and offset the carbon footprint of regular fossil fuel based fertilizer production and application

On November 20, 2009 the project was selected as one of 30 out of 223 to move to the Full Project Proposal stage. LBGP, at that time representing a limited partnership between ECB NA and ATCO Midstream (AML), submitted a Full Proposal (FP) with a final project size of 2.8 MW generation capacity on February 25, 2010. With project objectives remaining unchanged the project was approved for a $8,200,000 contribution by the CCEMC subject to various conditions. On March 28, 2011 LBGP signed a Contribution Agreement with the CCEMC. LBGP, now acting on behalf of Lethbridge Biogas LP (LP), a limited partnership between ECB NA and PlanET Biogas, was able to successfully complete financing for the project and on June 30, 2011 LBGP received a ‘Notice of Satisfaction Of Conditions’ from the CCEMC confirming that all conditions as outlined in the Contribution Agreement have been satisfied. LBGP completed partnership agreements and construction contracts and was able to start with construction activities for the Lethbridge biogas/cogeneration facility on August 12, 2011. The facility is located in the County of Lethbridge at 4456 – 8th Avenue North, Lethbridge, AB (Section 3, Township 9, Range 21, West of the 4th Meridian) immediately east of the City of Lethbridge east boundary. The facility and its components have been commissioned, operation has started and the official Ribbon Cutting/Opening ceremony is scheduled for December 4, 2013. The progress during the construction process of the facility has been documented and reported to the CCEMC with every project milestone (see Attachment A).

2.3 ECB Enviro North America Inc. (ECB NA)

ECB Enviro North America Inc. (ECB NA), located in Fort Macleod, AB, was incorporated under the Alberta Business Corporations Act in October in 2001 as an initiative of successful Alberta businessman closely related to the agriculture business, who believed in the future of the emerging markets of bio-energy in Canada. ECB NA’s management team combines successful business experience in Alberta’s agricultural and industrial sectors with international technical expertise in cogeneration and renewable energy projects.



ECB NA was the owner and developer of the Lethbridge biogas/cogeneration project and has brought the project through the stages of feasibility, regulatory approval, design & engineering and financing to a shovel-ready project. ECB NA, through its subsidiary ECB Lethbridge Co-Gen Ltd., is a limited partner in Lethbridge Biogas LP.

2.4 PlanET Biogas (PlanET)

PlanET Biogas is one of the world’s leading biogas plant suppliers. Founded in 1998, the company’s service portfolio covers all fields of biogas technology and component distribution: from planning, plant construction, refinement of biogas to natural gas quality and all the way to service and biological support from an in-house laboratory. PlanET’s RePowering division enables customers to increase the efficiency of their existing plants in a targeted fashion. At the same time, the modularly developed SYSTEMBIOGAS functional principle allows biogas plant operators and investors to react to new developments on the biogas market at any time. Over 200 employees currently work at the company headquarters in the German Muensterland alone. Other employees work in the international subsidiaries in the Netherlands, France and Canada. PlanET is also represented in the United Kingdom, Italy, Spain and Japan. PlanET already has successfully realized more than 300 biogas plants worldwide on a scale from 40 kW to several megawatts. PlanET, through its subsidiary PlanET Biogas Investments Inc., is a limited partner in Lethbridge Biogas LP.



3. FINAL OUTCOMES REPORT

3.1 Project Technology

LB built and operates a biogas/cogeneration facility that uses advanced anaerobic digester technology to extract biogas from organic feedstock in a technically controlled anaerobic environment. The system is designed to produce up to 26,000 m3 of combustible biogas (50-60% CH4, max. 200 ppm H2S) per day at a maximum Organic Loading Rate (OLR) of 4.0 kg VS/m3. The following site plan gives an overview of the current facility and its various components.

1 Scrubber Building/Biofilters 2 Receiving/Unloading & Process Building 3 Tank Farm and Secondary Containment Area (incl. 2 pre-storage tanks, 1 hydrolyzed

animal by-product storage tank, 3 anaerobic digesters, 1 digestate storage tank, technical container, 4 ferric chloride tanks)

4 Cogeneration Area (incl. 2 co-generation units, exhaust stack, switchgear building, transformer, MVI, emergency generator)

5 Emergency Flare

3.1.1 Receiving/Unloading Technology

Feedstock is delivered to the site by truck, truck weights are recorded with the on-site truck scale and trucks are unloaded in the receiving building. Trucks are currently unloaded in truck bay 1 only (liquid and solid organics).

1

2

2

3

3

4

5



Liquid feedstock in truck bay 1 is unloaded via a pump and a manifold and is stored in dedicated storage tanks (pre-storage 1 & 2) after the unloading process. The characteristics of the two (2) pre-storage tanks located in the secondary containment area with a gross volume of approx. 1,150 m3 (14m *8m) are:

• Reinforced, cast-in-place concrete tank (jump form system with tie-less forms) • In-floor and in-wall hot water heating • Man door • Biogas protective treatment of concrete vessel (complete interior) • Rigid high-density floor and wall insulation (double layer), protective cladding • One (1) submersible and laterally & vertically adjustable mid-sized ‘wing’ agitator

(7.5 kW) • Various inlets and outputs for feeding and discharge of substrate, biogas, air,

condensate, ferric chloride, etc. • Fill level and operating sensors • Over-/under pressure safety valves • Access platform • Inspection windows

The double membrane biogas storage & weather protection system allows for approximately 300 m3 of biogas storage inside of each pre-storage tank.

Solid feedstock in truck bay 1 is dumped into an underground solid feeding system. The solid feeding system (Vario) can pump chopped energy crops, solid manure, feed remains as well as other solid co-ferments via a liquid flushing system and a progressive cavity pump directly into the anaerobic digesters. The pump is equipped with a speed regulator which adjusts the feed rate in the pipeline under constant flow pressure. The feed screw also has a speed regulator to ensure variable solids feeding in the chute. The characteristics of the solid feeding/liquid flushing system are:

• Hydraulically powered in-floor hatch • Receiving hopper with a nominal capacity of 75 m3 • Individually propelled stainless steel conveyor lines • Hinged flaps for efficient conveying • Auger system • Liquid flushing system with progression cavity pump

Trucks that unload in truck bay 1 reload with digested slurry (digestate) from the digestate storage tank located in the secondary containment. Trucks drive onto the weigh scale for second time to record the load of digestate before leaving the facility. Digestate is stored in existing manure storage lagoons at participating dairy and/or hog operations and will be land applied at the appropriate time on agricultural land.



3.1.2 Air Cleaning Technology

All air from the receiving/process building potentially contaminated with NH3 and other VOC’s including small levels of H2S is treated with a two stage scrubber (acid & base) followed by a 100% redundant biological bio-filtration system. The receiving/unloading & process building is constantly kept under a slight negative pressure to trap odorous air within the building. Once the trucks enter the truck bays and overhead doors start to open, the ventilation system in the building ramps up air flow to maintain negative pressure in the building. The air treatment system is located in the scrubber building adjacent to the receiving building. The bio-filtration system uses wood material (bark from softwood) that is always kept at a certain temperature and level of moisture to biologically destroy VOC’s and other odorous components. The bio-filtration system consists of two (2) fully redundant biofilter chambers each capable of treating 30,000 m3/h. The biofilter chambers are also located adjacent to the receiving building.

3.1.3 Technical Container

The technical container located in the secondary containment is 12 m long (40 ft.) and was delivered as a pre-assembled unit to the site. All substrate pumping in and out of the system goes through the pumping manifolds in the technical container as well as the distribution of hot water process heat. Included are furthermore:

• Man doors • Air ventilation system • Control panels • Air compressor unit for pneumatic valves and sealing tracks in the field, inclusive

air cooling system and compressor units for the desulphurization system • Gas analyzer (CH4: 0 -100% vol.; O2: 0 - 25% vol.; H: 0 – 4000 ppm; H2S: 0 –

5,000 ppm)

3.1.4 Anaerobic Digestion Technology

The anaerobic digestion process operates mesophilically at around 40 degree C. The facility is equipped with three (3) concrete anaerobic digesters located in the secondary containment area with a gross digester volume of approximately 3,900 m3 each (25m *8m). The digester characteristics are:

• Reinforced, cast-in-place concrete tank (jump form system with tie-less forms) • In-floor and in-wall hot water heating • Man door



• Biogas protective treatment of concrete vessel in gas zone • Rigid high-density floor and wall insulation (double layer), protective cladding • Four (4) submersible and laterally & vertically adjustable mid-sized ‘wing’

agitators (7.5 kW each) • Various inlets and outputs for feeding and discharge of substrate, biogas, air,


The double membrane biogas storage & weather protection system allows for approximately 1,500 m3 of biogas storage inside of each digester. Each anaerobic digester can be fed with organic material from the pre-storage tanks, the solid feeding system and the hydrolyzed slurry storage tank. Digester feeding and digester emptying occurs at a constant rate to ensure an optimal mix and proper fill levels are maintained in the digesters.

Digestate following the anaerobic treatment is discharged into one (1) digestate storage tank located in the secondary containment area that has a gross volume of approximately 5,700 m3

(30m *8m). The characteristics of the digestate storage tank are:

• Reinforced, cast-in-place concrete tank (jump form system with tie-less forms) • In-floor and in-wall hot water heating • Man door • Biogas protective treatment of concrete vessel in gas zone • Rigid high-density floor and wall insulation (double layer), protective cladding • Four (4) submersible and laterally & vertically adjustable mid-sized ‘wing’

agitators (7.5 kW each) • Various inlets and outputs for feeding and discharge of substrate, biogas, air,


The double membrane biogas storage & weather protection system allows for approximately 2,100 m3 of biogas storage inside of the digestate storage tank.

3.1.5 Biogas Cleaning & Biogas Conditioning Technology

The composition of the biogas ranges in percent methane by weight from between 50 % to 60 %. The remainder of gas composition consists principally of carbon dioxide. The biogas also



contains trace amounts of H2S. The H2S in the biogas is removed through a biological process within the anaerobic digesters. A newly developed desulphurization fabric is optimally stretched over the tank with tension belts. The stainless steel column in the centre of the tank provides an additional point of support and simultaneously serves to deflect the belts. The belts are fastened to the exterior wall of the tank by anchor elements made of stainless steel. The desulphurization fabric creates the surface for organic bacteria that reduce the H2S to elemental sulfur in a reaction with small amounts of oxygen. As a back-up system and also used for the start-up, the anaerobic digesters are equipped with a chemical H2S cleaning system as well, that is based on dosing small amounts of ferric chloride into the system. Prior to the combustion process in the cogeneration units (CHP’s), the biogas is adjusted in moisture and temperature and passes through an activated carbon filter for a third layer of H2S removal if required.

3.1.6 Co-Generation Technology

Initially two (2) 2G fully containerized units with an electrical generation capacity of 1,425 kW, each featuring GE-Jenbacher engines, will use the biogas to produce electricity and process heat (see Attachment B). One of the units is equipped for fuel blending (biogas/natural gas). The facility is connected to the FortisAlberta distribution system at the 25 KV level. Switchgear that is located within a small building and an on-site transformer deliver and convert the 600V electricity as produced by the engines into 25KV and connect the facility to the Alberta power grid at all times. The facility can be taken off the grid through a transfer trip system by the utilities. An automatic transfer switch that is connected to an emergency generator ensures that in case of power outages or other upset conditions the facility will be able to maintain its key electric functions. Thermal energy recovered from the co-generation units is used within a closed loop glycol/water system to cover the thermal needs of the process.

3.1.7 Emergency Flare

The on-site emergency flare is capable of safely combusting all biogas produced on-site. The flare offers concealed combustion with an invisible flame. The flare is made up of a burner and a stainless steel flare tube, a hot-dip galvanized stand console, gas fan, gas valve line, ignition system (electric igniter and pilot plight) and switching system.



3.1.8 Control System & Visualization Software

The central control system provides the Lethbridge Biogas operator with the ability to monitor and control the process from any PC or via internet. Remote control is also possible via an auto dialer system and smart phone programming. The graphic user interface/visualization system is a touch screen system. The system also includes the main control cabinet located in the technical container, internal bus bar distribution system, network devices, circuit breakers, motor protection switches, transformers and relays, and a Siemens SPS unit.

3.1.9 Other Infrastructure

In addition to the core project technology as described above, Lethbridge Biogas had to install the following infrastructure for the project:

A) Industrial Runoff and Stormwater Retention Pond System including a composite liner system for the pond consisting of a

• minimum of 0.60 m thickness of compacted clay (constructed in lifts no more than 150 mm thick; hydraulic conductivity of 1x10-7 cm/sec or less and 98% Standard Proctor Density at 2-3% optimum moisture content)

• HDPE synthetic liner installed upon the compacted clay liner (60 mil or greater; ultraviolet light protected, capacity within the pond to store precipitation, industrial runoff and stormwater the following from a storm event; minimum of 0.5 meters of freeboard and prevent winds from driving the contents of the pond over the berm;

B) Secondary Containment System including

• a concrete wall that surrounds all of the tanks and provides secondary containment capable of containing 110% of the volume of the largest tank plus 10% of the aggregate capacity of all other tanks and the precipitation resulting from a storm event that falls within the secondary containment; and provides sufficient freeboard above the capacity in order to prevent winds from driving the contents of the secondary containment area over the concrete wall;

• a base pad within the secondary containment area that is sloped towards the east end of the area so that all precipitation falling upon or traversing that area collects in a sump so it can be transferred to the Industrial Runoff and Stormwater Retention Pond System;

• a composite liner system upon the base pad including a minimum of 0.60 m thickness of compacted clay (constructed in lifts no more than 150 mm thick; hydraulic conductivity of 1x10-7 cm/sec or less; and 98% Standard Proctor



Density at 2-3% optimum moisture content); an HDPE synthetic liner installed upon the compacted clay liner (60 mil or greater and ultraviolet light protected); and the synthetic liner in anchored and permanently sealed to the wall

• infrastructure that allows the stormwater resulting from a storm event that falls within the secondary containment to be pumped to the Industrial Runoff and Stormwater Retention Pond System

C) City Water Line

To connect with the facility to the existing water distribution system within the County of Lethbridge, Lethbridge Biogas had to install a 10 inch PVC water line from 8th Avenue North to the facility. Part of the water system was gate valves, plugs, reducers, elbows fire hydrants and road restoration work.

D) Ring Road

To allow weighing of the trucks and to facilitate truck movement on-site Lethbridge Biogas had to install a ring road around the secondary containment that connects the north side and the south side of the unloading building. A truck scale has been installed on the north side of the ring road.

3.2 Regulatory Approvals

The construction and operation of the Lethbridge biogas/cogeneration facility has been authorized through various approval processes with several regulatory agencies. The following regulatory approvals have been issued until November 30, 2013:

Regulatory Agency Approval/Amendment Issued County of Lethbridge Development Permit #2006-75 as

amended August 15,2006/July 25,2007/July

19, 2011

Alberta Environment and Sustainable Resources Development (ESRD)

001-224576-00 November 2, 2007 001-224576-01 April 1, 2009 001-224576-02 May 14, 2010 001-224576-03 October 7, 2011 001-224576-04 March 27, 2013 001-224576-05 September 26 , 2013

Alberta Utilities Commission (AUC) Connection Order U2010-171 May 14, 2010 Power Plant Approval U2011-180 April 28, 2011

Natural Resources Conservation Board (NRCB)

Authorization LA 134024 November 5, 2013

Municipal Affairs Variance No. G12.05 October 2, 2012

Superior Safety Codes Inc. AMA B 0077 11 LT August 16, 2011 AMA B 0027 12 LT April 23, 2012 AMA D 0028 12 LT April 24, 2012 AMA B 0077 12 LT August 22, 2012



3.3 Project Innovations

The Lethbridge Biogas cogeneration is unique in its process design, technology scope and scale and is the first one of its kind in Alberta and all over Canada.

A) Process Design: The facility is a large-scale, privately owned, commercial, off-farm biogas facility located in an industrial area close to an urban environment. It is designed to process multiple liquid and solid organic waste streams from various agricultural and agro-industrial sources (co-fermentation). The unique feedstock mix allows to maximize biogas production.

B) Technology: The facility is an advanced anaerobic digester system designed for high

efficiency and low energy consumption. The biological gas cleaning system based on the desulphurization fabric has been used in the Lethbridge facility for the first time. No other facility has incorporated a state of the art odour control system with a combination of wet scrubbing and biological air cleaning through redundant and enclosed wood-chip based biofilters. The incorporation of the high pressure thermal hydrolysis system will be the first commercial application for that technology (see Section 5).

C) Scope: The facility has an integrated 'Zero-Waste'(closed-loop) approach with use of all by-products of the anaerobic digestion process. Waste heat is captured from the co-gens for process heating and the digestate is used as a nutrient enriched organic fertilizer for agricultural purposes.

D) Size: The facility is capable of processing up to 150,000 t/a of liquid and solid organic feedstock including up to 20,000 t/a of animal by-products (ABP) while initially generating up to 2.85 MW with the potential to increase generation capacity to 4.2MW.

3.4 Project Performance

Project performance at this point can only be evaluated considering the amounts of feedstock quantities processed and electricity generated.

3.4.1 Feedstock

a) Process Start-Up

Lethbridge Biogas has started to fill the facility with organic feedstock on June 5, 2013. In the subsequent months until the end of September 2013 the facility has accepted approximately 18,000 t of organic product. Feedstock used was predominantly liquid dairy manure with some small amounts of liquid cheese whey. The main purpose during



this initial period was to get the anaerobic digesters up to operating temperature and establish a healthy biological system.

During the start-up process no complications did occur and the biological process was established without any third party inoculums. Methane content (CH4) in the biogas rose slowly but was initially not suited for use in the engines. Peaks in methane concentration of approximately 65 % did occur before the methane content was stabilized around 55 %, see Graph below.

Development of CH4 content from digester filling to engine commissioning (Digester 1)

b) Commissioning of Solid Feeding System (Vario)

After the establishment of a biologically healthy process, the facility has accepted approximately 8,500 t of liquid feedstock until November 30, 2013. At the same time solid and more energy rich feedstock was introduced into the process. The solid feeding system was successfully commissioned on October 21, 2013 and more than 400 t of solid feedstock have been processed since. Solid feedstock used so far was solid separated dairy and hog manure, chicken manure, waste potatoes, grocery waste and DAF. During the commissioning process some hardware & software adjustments have been made to the system.



c) Increased Substrate Feeding

Since November 11, 2013 substrate feeding rates (liquid & solid) have been increased and the system is operating automatically without continuous supervision. Gas quantity and gas quality have significantly improved and the methane content has currently been stabilised at around 60%, see Graph below. Feeding rates will continually be increased as more and more feedstock will be processed in the coming month.

Development of CH4 content since commissioning of solid feeding system (Digester 1)

Overall the anaerobic digester system is biologically stable, reacting normally and performing well as expected. Attachment C shows the variety of organic feedstock that can be processed in the Lethbridge biogas/cogeneration facility.

3.4.2 Electricity Production

a) Metering Program

Lethbridge Biogas has installed 2 bi-directional meters at the plant located in the switchgear building. Both meters are manufactured by Schneider Electric, model ION 7550:

• The ‘GROSS GEN’ meter (serial# PI-1207A777-03) is measuring gross generation. This meter has been installed for the purpose of accounting for eligible electricity production under the Bioenergy Producer Credit Program (BPCP)



• The ‘POI’ meter (serial# PI-1207A776-03) is measuring export into the FortisAlberta grid at the Point of Interconnection (POI). This meter is used for settlement with the Alberta Electric System Operator (AESO)

The plant load (parasitic load) itself is not metered but can be calculated as the difference between the metered values of ‘GROSS GEN’ and ‘POI’ Both meters have been calibrated at the factory and sealed by FortisBC Measurement – a Measurement Canada accredited meter verifier.

b) Engine Configuration

Lethbridge Biogas has currently installed 2 co-generation units packaged and delivered by 2G Energietechnik GmbH, Germany based on engines manufactured by GE/Jenbacher (Attachment B):

• CHP 1: Type JMS 420 GS-B.L (Biogas only), max. electrical output 1.426 MWel (100% Biogas), serial# JN-385/1

• CHP 2: Type JMS 420 GS-B.L (Biogas/Natural Gas), max electrical output 1.426

MW (100% biogas); max. 1,248 MWel (100% Natural Gas), serial# JN-385/2). This engine allows dual fuel operation with the use of either 100% biogas or 100% natural gas or any blend of biogas/natural gas.

Both engines are equipped with a gas flow meter, manufactured by Esters Elektronik GmbH, Germany. These flow meters measure the use of biogas used for electricity production. The measured flow is displayed on the engine module visualization screen with ‘Gas Counter’ for each engine. CHP 1 has been commissioned for natural gas operation on April 27, 2013 and has delivered the heat for starting up and commissioning the anaerobic digestion process. Natural gas based electricity has been exported to the Alberta Power Pool since then as well. CHP 1 & CHP 2 have both been commissioned for biogas operation on August 28, 2013. An unexpected breakdown of CHP 1 due to a mechanical failure of the crank shaft caused CHP 1 to be out of service between September 17, 2013 and October 18, 2013. The engine manufacturer replaced the engine block on a warranty claim and the engine is back in operation since October 19, 2013.



c) Electricity Generation

To-date Lethbridge Biogas has produced a total of 6,055.83 MWh of electricity (see Table below, including production until November 30, 2013). The following table shows the amounts of electricity generated (GROSS GEN) and sold (POI) to the Alberta Power Pool administered by the Alberta Electric System Operator (AESO) in 2013.

Month GROSS GEN

(as measured in MWh)

POI (as measured

in MWh)

Fuel Type

(% BG)

Plant Load (as calculated

in MWh)

Plant Load (in % of gross generation)

Process Heating & Start-Up (04-07 2013) Apr 113.41 111.77 0% 1.64 1.45%

May 644.54 644.32 0% 0.22 0.03% Jun 595.73 586.00 0% 9.73 1.63% Jul 871.05 845.95 0% 25.10 2.88%

Start Feeding & Biogas Production (08-11 2013) Aug 903.98 871.89 13.8% 32.09 3.55% Sep 952.35 912.82 39.53 4.15% Oct 992.00 937.33 19.7% 54.67 5.51%

Nov* 982.77 926.74 20.7% 56.03 5.70% TOTAL 6,055.83 5,836.82 219.01 3.62%

Note *: Data for November 2013 until Nov-30-2013 Due to the increased feeding rates in recent weeks and resulting increase in biogas quantity and quality the amount of electricity derived from biogas is steadily increasing. On November 30, 2013 CHP 1 produced 17.2 MWh hours (716 kW) of electricity exclusively derived from biogas which was the highest daily biogas generated electricity production in any 24 hour period since the facility came on-line. CHP 1 is running exclusively on biogas for 24/7 since November, 29 at 9.00 p.m. For December 2013 it is anticipated that the facility will produce well over 500 MWh of biogas generated electricity.

3.4.3 GHG Emission Reductions

Lethbridge Biogas has contracted Blue Source Canada to certify and register all Emission Reduction Credits arising from the Project and to represent Lethbridge Biogas in the sale or other marketing of such Emission Reduction Credits. Initial contact with the Air and Climate Change Policy Branch within Alberta Environment and Sustainable Resource Development (ESRD) revealed the following (see Attachment D):



• The project can use the flagged ‘Quantification Protocol for the Anaerobic Decomposition of Agricultural Materials’ in its current state for the crediting of biogas energy production and use providing it can be accurately separated from the natural gas component. As biogas flow and natural gas flows will be metered separately, Lethbridge Biogas will be able to use the current protocol.

BUT

• The landfill gas diversion model is currently being revised to address identified

risks and is unable to be used until revised. Once the landfill gas diversion methodology is revised this project will be able to use it on a go forward basis. Lethbridge biogas has started to divert organic material from landfill. Approximately 100 t have been diverted until November 30, 2013. In order to claim greenhouse credits under the revised protocol, it is anticipated that extensive records will have to be provided to demonstrate how long and where products have been previously land filled. The unknown status of the protocol and the anticipated requirements put some uncertainty on the evaluation of greenhouse gas credits from landfill diversion which is expected to deliver a significant amount of greenhouse gas credits over the lifetime of the project.

• This project will not be able to generate credit under the protocol from the

natural gas cogeneration. This is a new activity that will likely require a new protocol and must complete all the required stages of protocol development within Alberta's offset system. Although effectively reducing greenhouse gases by partly using natural gas for electricity generation, the project will currently not be able to generate greenhouse gas offsets under the current offset system. This is somewhat surprising as this policy contradicts all current political efforts on the Alberta power market to make a shift from coal fired power generation to more sustainable power generation based on clean natural gas within the next 10-15 years.

Because of the current uncertainty around the landfill protocol, the limited operational activities in 2013 and the high costs associated with the third party verification of GHG emission reductions, Lethbridge Biogas will likely postpone its 1st third party verification into Q1 of 2015. Initial reduction of GHG emissions for 2013 are estimated to reach between 500 -1,000 t CO2e.



3.5 Project Impact

In its very short operational lifetime to-date the Lethbridge facility has already made a significant impact on the local community:

A) Employment: Lethbridge Biogas is currently employing 6 people full-time. Once at full capacity it is anticipated that up to 10 people will work full-time at the facility.

B) Waste Management: Lethbridge Biogas offers the only ‘green’ solution for of disposal of organic waste material in the area and as a result of this Lethbridge Biogas has been approached by various waste management companies and waste haulers. A pilot program has been started with the world’s largest retail organization to dispose of grocery waste from the local stores in the Lethbridge facility. Lethbridge Biogas was also able to lower disposal costs for one of Alberta’s large hog processing facilities. By-products like peptone and DAF are now being disposed of environmentally sustainable in the Lethbridge facility.

C) Capacity Building: The Lethbridge facility already served as technology example for another anaerobic digestion facility that is currently under construction in the hamlet of Chin, Alberta, approximately 10 minutes east outside of Coaldale. Although significantly smaller in size, the GrowTec facility will use the same anaerobic digestion technology to process liquid and solid residues from potato processing and other organic materials to generate 633 kW of renewable electricity.

D) Societal Benefits: Lethbridge Biogas has been invited for round table discussions with local post secondary educational facilities and research organizations to discuss potential collaboration with industry. The close proximity of the Lethbridge biogas/cogeneration facility to several of these organizations (e.g. Lethbridge College, AAFC Lethbridge Research Centre) will allow the establishment of advanced educational opportunities as well as new research opportunities.



4. FINAL FINANCIAL REPORT

4.1 Project Expenses

Eligible project expenses total $28,575,741 until November 30, 2013 and are related to the milestones as follows:

• Phase 1 - Milestone 1: $ 4,187,775 • Phase 1 - Milestone 2: $ 3,819,680 • Phase 1 - Milestone 3A: $16,888,127 • Phase 1/2 - Milestone 3B: $ 3,185,761 • Phase 2: - Jul-Nov 2013: $ 494,399

Project expenses included in Milestone 3B did in part include operational expenses originally planned for Phase 2 of the project. When submitting expenses for Milestone 3B Lethbridge Biogas has been advised by PWC to not report these expenses in the online reporting period for Milestone 3B.

4.2 Project Contributions

Project contributions provided by CCEMC and the project partners total $28,575,741 until November 30, 2013 and are as follows:

• Agriculture Financial Services Corporation (AFSC): $ 5,000,000 • Climate Change and Emissions Management (CCEMC) Corporation: $ 8,200,000

(incl. holdback) • Department of Energy: $ 6,448,016 • PlanET: $ 8,200,000 • Lethbridge Biogas: $ 727,725

4.3 Project Revenues

Lethbridge Biogas commissioned the 1st engine on natural gas on April 27, 2013 and is producing electricity for export into the Alberta grid since that time. On August 28, 2013 both engines were commissioned on biogas and the second engine started to produce first quantities of biogas generated electricity. Project revenues until November 30, 2013, predominantly received from electricity sales to the AESO, total $826,327.



5. CONCLUSION & NEXT STEPS The Lethbridge biogas/cogeneration has been successfully implemented between March 2011 and November 2013 through the stages of development, construction, commissioning, start-up and initial operation. The project demonstrates the use of innovative technologies to reduce GHG emissions through the use of renewable energy sources and will directly contribute to Alberta’s long-term Climate Change goals. This demonstration will greatly increase the chances of success of commercial-scale biogas development in Alberta and will result in future opportunities throughout Alberta, Canada and abroad. A direct spin-off was already achieved with the start of construction for the GrowTEC anaerobic digestion facility in Chin, AB. The Lethbridge biogas/cogeneration is an important rural development project that already has economic, environmental and societal benefits for the region through waste reduction, energy creation and advanced technology application. The implementation of the thermal hydrolysis process (THD) will be the major focus for Lethbridge Biogas in 2014. The first commercial application of the THD will allow animal by-products incl. Specified Risk Material (SRM) to be processed in the Lethbridge facility.

Some infrastructure for the THD process such as the process building, distribution manifolds, process piping, hydraulic floor hatch, the hydrolyzed animal by-product storage tank and the hot-oil heater system are already installed. The main components of the THD had to be delayed because the supplier originally selected could not deliver the system because. A new supplier has been chosen and a potential scope of delivery has been discussed. A purchase order could not be issued at this point because of cash flow issues within the project. It is anticipated that Lethbridge Biogas will be able to place an order for the THD system within Q1 of 2014. This would allow for the system to be delivered, installed and commissioned in Q3/Q4 of 2014.

The THD system will pre-treat animal by-products before they are pumped into the anaerobic digestion process. The thermal hydrolysis vessel and associated components will be located in the process building adjacent to the receiving building. The thermal hydrolysis will be a batch process and will employ heat and pressure to the ground up animal by-products, to break longer chain organic compounds into short-chain fragments better suited for consumption by micro-organisms. The thermal hydrolysis’ operating temperature and pressure will be 180 ºC at 12 bar pressure, respectively. The cycle time, which includes loading, treatment and unloading, will be 160 minutes which includes a treatment time of 40 minutes. Following the 40 minute treatment time, the vessel will be allowed to depressurize at a controlled rate. The material will be discharged into a flash tank before outside storage of the hydrolyzed material in a 300 m3



concrete storage tank with a fixed concrete roof located in the secondary containment area (already installed). The energy for the thermal hydrolysis process will be produced by a natural gas fired 3,000 kW hot oil heater and associated components. The heat will be delivered to the thermal hydrolysis process through indirect heating.

The operating parameters of this thermal hydrolysis process have been approved by the Canadian Food Inspection Agency (CFIA) for the safe treatment of SRM and the destruction of prions.

Because of the current uncertainty around the landfill quantification protocol a detailed assessment of the impact of the delayed implementation of the THD system is very difficult. Given the long term nature of the project, it is anticipated that a 6-9 month delay will not significantly impact the projects ability to reduce GHG emissions.



ATTACHMENT A



CONSTRUCTION & COMMISSIONING ACTIVITIES AUGUST 2011 – NOVEMBER 2013

AUGUST 12

(START OF CONSTRUCTION)

AUGUST 22

(SITE GRADING & WEST CULVERT)

AUGUST 30

(EXCAVATION FOR SECONDARY

CONTAINMENT)

SEPTEMBER 02

(FINISHING OF ROUGH CUTS)



SEPTEMBER 07

(WORK ON CLAY LINER)

SEPTEMBER 18

(PLACEMENT OF HDPE LINER)

SEPTEMBER 22

(PARTIAL BACKFILL & ROAD ACCESS TO

TANKS)

SEPTEMBER 28

(PLACEMENT OF INSULATION &

REBAR)

SEPTEMBER 30

(START OF CONCRETE WORK)



OCTOBER 04

(3RD DIGESTER FOUNDATION

POURED)

OCTOBER 05

(SITE VISIT BY PLANET DELEGATION

FROM GERMANY)

OCTOBER 14

(ALL DIGESTER & TANK FOUNDATIONS

COMPLETE)

NOVEMBER 3

(WEEPING TILE, DRAINAGE SUMPS & PARTIAL BACKFILL)

NOVEMBER 10

(CONCRETE FOOTINGS FOR CENTER PIERS)



NOVEMBER 11

(SITE WINTERIZED)

APRIL 09/12

(START ON CONCRETE

WORK FOR TANK

WALLS)

APRIL 16/12

(1ST WALL RING ON

DIGESTER 1)

APRIL 30/12

(6TH WALL RING ON

DIGESTER 1)

MAY 07/12

(2ND WALL RING ON

PRE-STORAGE I & SITE

PREP ON EAST BLDG./ PARKING AREA)



MAY 15/12

(1ST DIGESTER

INSULATED, 6TH WALL

RING ON PRE-STORAGE

I & 2ND WALL RING ON

2ND DIGESTER)

MAY 22/12

(PRE-STORAGE I FINISHED, 2ND WALL

RING ON PRE-STORAGE

II & 4TH WALL RING ON

DIGESTER 2)

MAY 28/12

(CLADDING ON 1ST

DIGESTER, 6TH WALL

RING ON 2ND DIGESTER

& 5TH WALL RING ON

PRE-STORAGE II)

JUNE 12/12

(CLADDING ON 1ST

DIGESTER AND PRE-STORAGE I & II)

JUNE 20/12

(1ST WALL ON SRM

BUFFER TANK & START

OF TANK EQUIPMENT

INSTALLATION)



JUNE 26/12

(SRM BUFFER TANK

COMPLETED & 2ND

DIGESTER INSULATED

& CLADDED)

JULY 03/12

(START OF

EXCAVATION FOR

RECEIVING/PROCESS

BLDG. BASEMENT)

JULY 06/12

(EXCAVATION

PROGRESS)

JULY 11/12

(SRM BUFFER TANK

INSULATED & CLADDED

& START OF BUILDING

FOUNDATION)

JULY 17/12

(BASEMENT FLOOR IN

RECEIVING/PROCESS

BLDG.)



JULY 31/12

(REBAR

RECEIVING/PROCESS

BLDG. BASEMENT &

SITE PREP FOR CO-GENS AND SWITCHGEAR

BLDG.)

AUGUST 08/12

(PROGRESS

RECEIVING/PROCESS

BLDG. BASEMENT &

START OF RETENTION

POND EXCAVATION)

AUGUST 11/12

(1ST BASEMENT WALLS

POURED & 3RD WALL

RING ON 3RD DIGESTER)

AUGUST 16/12

(BASEMENT WALLS

COMPLETED & 4TH WALL

RING ON 3RD DIGESTER)

AUGUST 23/12

(START OF BACKFILL

FOR BASEMENT)



AUGUST 27/12

(6TH WALL RING ON 3RD

DIGESTER & START OF

MIXER INSTALLATIONS)

AUGUST 31/12

1ST WALL RING ON

POST-STORAGE &

START OF PIPE WORK

SEPTEMBER 05/12

2ND WALL RING ON

POST-STORAGE & MUD

SLAB FOR PROCESS

BLDG. FOUNDATION

SEPTEMBER 07/12

3RD WALL RING ON

POST-STORAGE &

START OF

INSTALLATION OF TANK

CENTER PIERS

SEPTEMBER 11/12

TANK CENTER PIERS

INSTALLED &

DRAINAGE PIPE

INSTALLED IN

RETENTION POND



SEPTEMBER 14/12

5TH WALL RING ON

POST-STORAGE & 3RD

DIGESTER INSULATED

& CLADDED

SEPTEMBER 17/12

6TH WALL RING ON

POST-STORAGE &

START OF SHORING

FOR FLOOR SLAB OF

RECEIVING BLDG.

SEPTEMBER 20/12

STAIRS TO SCRUBBER

BLDG. & WESTERN

ONE BARBECUE

SEPTEMBER 24/12

PROGRESS IN PIPE

WORK & ASSEMBLY OF

THE HATCHES FOR

FLOOR SLAB OF

RECEIVING BLDG.

SEPTEMBER 25/12

PLACEMENT OF FLOOR

HATCHES FOR

RECEIVING BLDG.



SEPTEMBER 27/12

FOUNDATION FOR

SWITCHGEAR BLDG. &

START OF SOUTH

CONTAINMENT WALL

OCTOBER 01/12

HDPE LINER

INSTALLED IN

RETENTION POND &

ERECTION OF

SWITCHGEAR BLDG.

OCTOBER 04/12

CLADDING ON POST

STORAGE (LAST

TANK!!) &

SWITCHGEAR BLDG. POURED

OCTOBER 10/12

GRADE BEAMS FOR

PROCESS BLDG. &

RECEIVING BLDG. POURED

OCTOBER 12/12

REBAR IN SOUTH

CONTAINMENT WALL &

START OF EXCAVATION

FOR WATER PIPELINE



OCTOBER 16/12

START OF NORTH

CONTAINMENT WALL &

FOOTINGS FOR CO-GEN

UNITS

OCTOBER 18/12

COMPLETION OF SOUTH

CONTAINMENT WALL &

TECHNICAL UNIT IN

PLACE

OCTOBER 23/12

A WINTER DAY...

NOVEMBER 02/12

REBAR IN NORTH

CONTAINMENT WALL &

PREP WORK FOR

RECEIVING/PROCESS

BLDG. FLOOR SLAB

NOVEMBER 06/12

COMPLETION OF CO-GEN FOOTINGS &

START OF ROOF

INSTALLATION ON

TANKS & DIGESTERS



NOVEMBER 07/12

START OF

COMMISSIONING

ACTIVITIES

NOVEMBER 08/12

FOUNDATION FOR CO-GEN STACK & ROOFS

FOR PRE-STORAGE I &

II COMMISSIONED

NOVEMBER 10/12

ARRIVAL AND

PLACEMENT OF 1ST CO-GEN

NOVEMBER 13/12

COMMISSIONING OF

PIPING & PROGRESS

ON WATER LINE

NOVEMBER 14/12

ROOF ON DIGESTER 2

COMMISSIONED &

HYDROVAC FOR WATER

LINE



NOVEMBER 16/12

POURING OF FLOOR

SLAB FOR

RECEIVING/PROCESS

BLDG & EXCAVATION

FOR WEIGH SCALE

NOVEMBER 19/12

INSTALLATION OF GRID

CONNECTION & MVI &

ROOF ON DIGESTER 3

COMMISSIONED

NOVEMBER 23/12

MUD SLAB FOR WEIGH

SCALE & PROGRESS ON

WATER LINE

NOVEMBER 26/12

REBAR FOR WEIGH

SCALE & FOUNDATION

WORK ON BIO-FILTERS

NOVEMBER 28/12

ROOF ON DIGESTER 1

COMMISSIONED &

FLOOR SLAB FOR

WEIGH SCALE POURED



DECEMBER 04/12

FOUNDATION

COMPLETED FOR

BIOFILTER/SCRUBBER

BLDG. & REPAIR WORK

ON LINER

DECEMBER 13/12

DRILLING OF

GROUNDWATER

MONITORING WELLS &

EAST WALL OF

PROCESS BLDG.

DECEMBER 20/12

START OF EAST

CONTAINMENT WALL &

COMPLETION OF

CONCRETE WORK ON

RECEIVING/PROCESS

BLDG.

JANUARY 04/13

(GAS LINE HOOK UP &

WALLS ON NORTH

BIOFILTER)

JANUARY 08/13

(PREP WORK FOR

BLDG. ERECTION &

DELIVERY OF HOT OIL

SYSTEM)



JANUARY 10/13

(START OF BLDG. ERECTION & WALLS ON

SOUTH BIOFILTER)

JANUARY 11/13

PROGRESS ON BLDG. ERECTION & DELIVERY

OF WET SCRUBBER

SYSTEM)

JANUARY 15/13

PROGRESS ON BLDG. ERECTION &

INSTALLATION OF

TRANSFORMER)

JANUARY 17/13

INSTALLATION OF

SWITCHGEAR &

INSTALLATION OF

WEIGH SCALE DECK)

JANUARY 23/13

LINER INSTALLATION

ON BLDG. &

INSTALLATION OF

CATWALKS ON

DIGESTERS & TANKS



JANUARY 24/13

INSULATION & REBAR

FOR NORTH BIOFILTER

SLAB & PREP WORK

FOR EMERGENCY FLARE

FOUNDATION

JANUARY 25/13

ROOF ON POST- STORAGE

COMMISSIONED &

SLAB FOR NORTH

BIOFILTER

JANUARY 26/13

ARRIVAL AND

PLACEMENT OF 2ND CO-GEN

JANUARY 28/13

START OF

INSTALLATION OF

AUXILIARY CO-GEN

EQUIPMENT

JANUARY 31/13

PRIMARY STEEL FOR

OFFICE & ROOF

INSTALLATIONS FOR

CO-GENS ASSEMBLED



FEBRUARY 04/13

INSTALLATION OF CO-GEN EXHAUST STACK &

BIOGAS COOLING UNITS

FEBRUARY 07/13

MEZZANINE IN

RECEIVING/PROCESS

BLDG & EMERGENCY

FLARE PAD

FEBRUARY 11/13

START OF BLDG. INSULATION &

CLADDING & SHORING

FOR SOUTH BIOFILTER

ROOF

FEBRUARY 12/13

INSULATION &

CLADDING ON EAST

PROCESS BLDG. WALL &

NATURAL GAS CONNECT

FOR DUAL-FUEL ENGINE

FEBRUARY 14/13

FENCING FOR HIGH

VOLTAGE

TRANSFORMER &

INSULATION &

CLADDING ON SOUTH

PROCESS BLDG. WALL



FEBRUARY 15/13

INSTALLATION OF HIGH

VOLTAGE CABLES FROM

CO-GENS TO

SWITCHGEAR

FEBRUARY 19/13

INSULATION &

CLADDING ON NORTH &

SOUTH RECEIVING

BLDG. WALLS

FEBRUARY 20/13

EXHAUST PIPE

CONNECTIONS FROM

CO-GENS TO STACK &

SW CORNER OF

CONTAINMENT WALL

FEBRUARY 26/13

NE CORNER OF

CONTAINMENT WALL &

REBAR FOR NORTH &

SOUTH BIOFILTER

ROOFS

FEBRUARY 28/13

INSTALLATION OF

TRANSFORMER FENCE &

FACILITY OVERVIEW



MARCH 05/13

INSTALLATION OF

EMERGENCY FLARE &

INSTALLATION OF GAS

METER

MARCH 07/13

NW CORNER OF

CONTAINMENT WALL &

INSTALLATION OF BUS

BAR (SWITCHGEAR TO

TRANSFORMER)

MARCH 08/13

INSTALLATION OF

OVERHEAD DOORS IN

RECEIVING BLDG. &

INSULATION &

CLADDING ON NORTH

BIOFILTER/OFFICE

MARCH 11/13

CONTAINMENT

BACKFILL SOUTH SIDE

& LINER ATTACHMENT

TO CONTAINMENT WALL

MARCH 13/13

START OF SCRUBBER

EQUIPMENT

INSTALLATION &

CONTAINMENT

LANDSCAPING



MARCH 18/13

ATTACHMENT OF LINER

TO RECEIVING BLDG. &

SEPARATION WALL IN

RECEIVING BLDG.

MARCH 20/13

INSULATION/CLADDING

ON RECEIVING BLDG. &

BIOFILTER COMPLETED

& INSTALLATION OF

WET SCRUBBER

MARCH 25/13

RECEIVING BLDG. INCL. BIOFILTERS AND

OFFICE ENCLOSED &

COMMISSIONING OF 1ST

ENGINE

MARCH 27/13

COMPLETION OF

BIOGAS PIPING &

START OF

INSTALLATION OF

VENTILATION SYSTEM

IN RECEIVING BLDG.

APRIL 03/13

BACKFILL IN

CONTAINMENT AREA &

FINISHED SEPARATION

WALL IN RECEIVING

BLDG.



APRIL 08/13

POLES FOR FINAL(SE) CORNER OF

CONTAINMENT WALL &

INSTALLATION OF

FINAL GAS OVERFLOW

APRIL 09/13

INSTALLATION OF

VENTILATION/HVAC

FOR OFFICE &

INSTALLATION OF

STAIRS TO DIGESTERS

APRIL 11/13

BACKFILL IN

CONTAINMENT

COMPLETED &

INSTALLATION OF

VENTILATION/HVAC

FOR RECEIVING BLDG.

APRIL 12/13

CONCRETE PAD FOR

EMERGENCY

GENERATOR &

CONCRETE LANDING

PADS FOR STAIRS TO

DIGESTERS

APRIL 18/13

INSTALLATION OF

REMOVABLE PANELS IN

RECEIVING BLDG. &

CONCRETE LANDING

PAD FOR OFFICE STAIRS



APRIL 26/13

RE-COMMISSIONING OF

1ST ENGINE &

SUCCESSFUL

SYNCHRONIZATION

WITH FORTISALBERTA

GRID

APRIL 27/13

FACILITY OVERVIEW –

WE ARE PRODUCING

POWER!

MAY 02/13

INSTALLATION OF HOT

OIL SYSTEM &

INSTALLATION OF UNIT

HEATERS IN RECEIVING

BLDG.

MAY 13/13

LAST (SE) CORNER OF

CONTAINMENT WALL

CLOSED &

INSTALLATION OF SUMP

FOR DIGESTATE PUMP

MAY 15/13

INSTALLATION OF

OFFICE STAIRS &

INSTALLATION OF

EMERGENCY

GENERATOR



MAY 21/13

1ST TRUCK AND TRAILER

UNIT READY TO ROLL

MAY 27/13

INSTALLATION OF

PERFORATED BIOFILTER

FLOORS & COMPLETION

OF SPRINKLER SYSTEM

JUNE 05/13

FIRST LOAD OF

MANURE HAULED INTO

THE PLANT (START OF

WET COMMISSIONING)

JUNE 12/13

INSTALLATION OF

MAKE-UP AIR UNIT

HEATER &

INSTALLATION OF

SOLID FEEDING SYSTEM

(VARIO)

JULY 10/13

COMMISSIONING OF

EMERGENCY FLARE

(FACILITY IS

PRODUCING BIOGAS)



JULY 26/13

INSTALLATION OF GAS

METER FOR RECEIVING

BLDG. &

COMMISSIONING OF

HYDRAULIC HATCHES

SEPTEMBER 23/13

GRAVELING OF RING

ROAD (SOUTH SIDE) &

OFFICE FRAMING

SEPTEMBER 28/13

ENGINE BLOCK REPLACEMENT ON CO-

GEN #1

OCTOBER 21/13

FILLING OF BIOFILTER # COMMISSIONING OF SOLID FEEDING SYSTEM

(VARIO)

OCTOBER 26/13

FACILITY OVERVIEW



ATTACHMENT B

ATTACHMENT C



Organic Feedstock for

Lethbridge Biogas Cogeneration Plant

Feedstock Description Sources

A. LIVESTOCK MANURES1

Dairy Manure

Manure (raw and/or separated) from dairy operations

Intensive Livestock Operations (ILO)

Hog Manure Manure (raw and/or separated) from hog operations

Poultry Manure Manure from poultry operations

Beef Manure2 Manure from feedlot operations

B. ORGANIC FOOD RESSOURCES3

B.1 Fats, Oils and Greases (FOG)

Dissolved Air Flotation Slurry (DAF)/ Centrifuged Dissolved Air Flotation Slurry (CDAF)

Fats & proteins skimmed from wash water

Slaughterhouses, meat packing operations

Grease Trap Fat & Food Interceptor Solids

Fats, oils & greases captured in grease traps & food interceptors

Restaurants, food processors, cafeterias, grocery stores

Used Vegetable Oil Vegetable oil used for deep frying

Mixed Processed Meat & Fish Wastes

Cooked & uncooked meat & fish residues

Food processors, meat packers, canneries

B.2 Food Processing Residues

Oils Seed Processing Residues Residues from extraction oils from seed incl. canola cake canola oil, bleaching clay

Oil seed processors

Feed Mill Residues Dust & wet grain residues Feed mills, farm operations

1 Estimated to be >50% of annual feedstock quantity processed (by weight) 2 Only suitable if without any mechanical contamination 3 Estimated to be 20-30% of annual feedstock quantity processed (by weight)



Cereal, Grain & Spice Processing Residues

Grain dust, husks, hulls, billies Grain processors, elevators, flour mills, cereal processors

Fruit & Vegetable Residues Pomace, peelings, rinds, juices Vegetable processors, juice processors, canneries, wineries

Corn Processing Residues Effluent from corn wet milling, stillage, distillers grain, silage, squeeze

Distillers, breweries, ethanol plants, food processors, starch producers

Beet Processing Residues Beets, beet tops, trash, tailings, molasses

Sugar production

Potato Processing Residues Potato sludge, peelings, chips Potato plants

Dairy Processing Residues Whey, milk, ice cream, proteins, wash water & other residues

Cheese factories, dairy processors

Aerobic Sludge Aerobic sludge from non-municipal wastewater treatment

Food processors

Pet Food Residues Pet food Pet food processors

Process Water Liquid residues, wash water Food processors

B.3 Kitchen & Market Residues

Bakery & Bread Residues Dough, flour, yeast & crumbs Bakeries, pizza parlours, restaurants, cafeterias

Confectionary Residues Candies & cookies Food processors

Mixed Food/Kitchen Residues Cooked & treated vegetables, fruits & grains, frozen food

Food processors, restaurants, grocery stores, cafeterias, hospitals, universities

C. ANIMAL BY-PRODUCTS4

Animal Carcasses & Animal Parts

Deadstock (cattle, hog, poultry, horse, bison), roadkill (deer, elk, moose)

Intensive livestock operations, slaughterhouses, packing plants

4 Estimated to be 10-20% of annual feedstock quantity processed (by weight). Animal by-products that are legally

classified as Specified Risk Material (SRM) will be pre-treated with thermal hydrolysis at 180 degree C, 12 bar for 40 minutes as required by the Canadian Food Inspection Agency (CFIA).



Animal Entrails Stomach & intestines from slaughtered animals

Slaughterhouses, packing plants

Animal Blood Blood drained & collected from slaughtered animals

Paunch Manure Manure removed from stomachs of slaughtered animals

D. OTHER

Glycerin/Glycerol Alcohol by-product Industrial biodiesel production

Horticultural Residues Residues from plants & flowers Greenhouses, garden centers, flower shops

Green (Garden) Residues Grass Municipalities, households

Energy Crops Silage (corn, grain, grass) Farm operations

Pulp & Paper Residues Sludge Paper mills

Disclaimer: Feedstock list is preliminary at this time and shows all feedstock currently considered that the plant will be technically capable of processing. Not all feedstock might be relevant for the Lethbridge area and only feedstock will be used that is suitable for the sensitive biological diet at the time a feedstock becomes potentially available. Biological suitability will be determined by Lethbridge Biogas through feedstock samples and microbiological analysis. Sampling and testing of digested sludge will follow the requirements as outlined in Section 4.4.12 of approval #224576-00-00 and its amendments.



ATTACHMENT D

2.85 mw lethbridge biogas/cogeneration facilty project … · 2.85 mw lethbridge...

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